The determination and measurement of the different phases present in a multi-phase produced fluid flowstream in a cased wellbore is very useful information for oilfield operators in order for them optimize production from downhole reservoirs. Produced flowstreams typically comprise free gas, water, or oil in any combination thereof. Uniquely determining the gas phase (hereafter referred to as “gas holdup”) present as a function of depth in a wellbore is particularly important. Many current generation production logging tools have had limited success in determining gas holdup since gas production often results in laminated, or partially laminated flowstreams, while the production logging tools, such as gamma-gamma fluid density logging tools, do not make measurements responsive to the full-bore flowstream. In the context of the art, the term “full-bore” means a measurement of liquid properties with virtually equal precision and accuracy over the entire cross section of the flow stream. Electrical resistivity based production logging tools have also been hampered by the fact that the electrical resistivities of oil and gas are both very high (and hard to distinguish), and the resistivity measurements are strongly dependent on the salinity of the water in the flowstream.
One relatively recent development of a full-bore gas holdup measurement tool is disclosed in U.S. Pat. No. 5,359,195. This tool used a low energy gamma ray source shielded from a very short-spaced gamma ray detector. Low energy gamma rays from the source are scattered primarily within the borehole fluid surrounding the tool and the scattered gamma radiation is detected by the gamma ray detector within the tool. All detected gamma rays are counted in a single measurement, which is then calibrated for the inside diameter (“ID”) of the well casing, and subsequently converted into an estimate of gas holdup. The higher the recorded scattered gamma ray count rate, the lower the gas holdup. One feature of this measurement is that, due to the low gamma ray source energy, any gamma rays that penetrated the well casing and are scatted back toward the detector cannot re-penetrate the well casing due to photoelectric absorption. This effect advantageously makes the measurements made by the tool insensitive to variations in the properties of the materials outside the casing and sensitive to fluid properties within the casing. This measurement technique has been useful, but is limited by the fact that the single measurement made by the tool is sensitive to the flowstream lamination and salinity, in addition to gas holdup. Unfortunately, a single count rate measurement cannot be used to resolve three unknown parameters.
A modification of the method disclosed in U.S. Pat. No. 5,359,195 utilizes a separate additional gamma-gamma fluid density measurement, and is disclosed in U.S. Pat. No. 5,552,598. Using this modified method, a fluid density measurement is combined with a gas holdup measurement to qualitatively determine if flow is laminated or dispersed (homogeneous). Since the fluid density measurement is sensitive to the fluid only in the center of the borehole, and the gas holdup tool disclosed in U.S. Pat. No. 5,359,195 is a full-bore measurement, a difference gas in holdup between the two measurements is used as a qualitative indicator of laminated flow. The combination measurement disclosed in U.S. Pat. No. 5,552,598 is, however, still sensitive to water salinity effects and to situations when the gas and liquids are partially mixed. The system disclosed in U.S. Pat. No. 5,552,598 also requires the use of two separate gamma ray sources thereby creating associated handling, storage, and safety issues. The separate fluid density tool string and source also require additional capital and operational expenses.